Electric power distribution networks are used by the electric utilities to deliver electricity from generating plants to customers. Although the actual distribution voltages will vary from utility to utility, in a typical network, three-phase power at high voltage 345,000 volts phase-to-phase (345 KV) is delivered to multiple high voltage substations at which transformers step this high voltage down to a lower three-phase voltage 115 KV. Multiple transmission substations further lower the voltage to 69 KV. This 69 KV three-phase power then feeds multiple distribution substations whose transformers further step down the voltage to the distribution voltage (12,470 volts phase-to-phase) and separate the power into three single-phase feeder cables. Typically, these feeder cables operate at 7,200 volts phase-to-ground. Each of these feeder cables branch into multiple circuits to power a plurality of local pole-mounted or pad-mounted transformers which step the voltage down to a final voltage of 120 and 240 volts for delivery to the commercial and residential customers.
The instantaneous phases of the three conductors in a three-phase system are separated by 120 degrees. A phase attribute of A, B, or C is typically assigned to each of the three conductors to identify them. The initial assignment of phase attribute to each of the three conductors typically takes place at a transmission or distribution substation and this assignment is somewhat arbitrary. The attributes assigned at the substations become known as the tagging reference phases for that substation because the goal is to consistently tag, mark, or identify each conductor with its proper phase attribute throughout the substation's distribution region.
Utilities have many reasons for accurately identifying the phase of each conductor in their utility. Examples are load balancing to reduce neutral current flow, faster service restoration after outages, and for distribution automation purposes.
Most currently available phase identification instruments use GPS timing signals to obtain instantaneous phase measurements at a reference location and field location at the same instant of time. The phase attribute at the reference location is known which allows the phase attribute at the field location to be determined. For example, if the reference location phase attribute is B and the instantaneous phase measured at both locations are the same, then the field location phase attribute is also B. If the instantaneous field location phase is leading or lagging the instantaneous reference location phase by 120 degrees, then the field location phase attribute is either A or C depending on the utilities known phase rotation.
To identify the field location phase attribute, the instantaneous phases at both locations have to be compared. Current phase identification instruments differ primarily in the method they each use to communicate the instantaneous phase reading between the reference location unit and the field location unit. Most manufacturers implement a real-time communication system using cell phones. Piesinger's, U.S. Pat. Nos. 6,667,610 and 7,031,859 describe a phase identification method that does not require real-time cell phone communication.
Current real-time phase identification systems have a number of shortcomings that make those system difficult to use. In particular, there are 3 primary problems with all current real-time phase identification systems that the present invention overcomes.
The first problem is that current systems require that the user install a dedicated phone line at the reference location. This is both a cost factor and an operational problem in that only one field user can access the reference location at the same time. Other users will receive a busy signal until the current user finishes his field measurements and disconnects from the system.
A second problem is that field cell phone coverage is marginal in most rural areas of the country. Without cell phone service, most current real-time phase identification systems cannot be used in those areas.
A third problem is that no current real-time phase identification system implements an easy method to account for tagging reference phase. Tagging reference phase is the most confusing aspect of phase identification for most linemen. Every time high voltage is stepped down to a lower voltage using a delta-wye or wye-delta transformer, a 30 degree phase rotation occurs. Without an easy way to account for these phase rotations, field phase attribute readings are meaningless.
Accordingly, it is the object of the present invention to provide a new and improved real-time method of identifying the phase of a conductor that solves these problems, overcomes other shortcomings, adds new features, and is easier for line crews to use.